CA1082589A - Method of consolidating a subterranean formation - Google Patents
Method of consolidating a subterranean formationInfo
- Publication number
- CA1082589A CA1082589A CA305,936A CA305936A CA1082589A CA 1082589 A CA1082589 A CA 1082589A CA 305936 A CA305936 A CA 305936A CA 1082589 A CA1082589 A CA 1082589A
- Authority
- CA
- Canada
- Prior art keywords
- fluid
- formation
- nonaqueous
- wellbore
- aqueous
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Expired
Links
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/025—Consolidation of loose sand or the like round the wells without excessively decreasing the permeability thereof
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/501—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls using spacer compositions
Abstract
ABSTRACT OF THE DISCLOSURE
A method of preventing the failure of a sand consolidation treatment due to contamination of the resinous material with aqueous rathole fluids during injection is described. The method involves displacing the aqueous rathole fluids with a dense, nonaqueous liquid prior to introducing the resinous material into the formation.
A method of preventing the failure of a sand consolidation treatment due to contamination of the resinous material with aqueous rathole fluids during injection is described. The method involves displacing the aqueous rathole fluids with a dense, nonaqueous liquid prior to introducing the resinous material into the formation.
Description
~al8258!~ :
1 BACKGROUND OF THE INVENTION ~-
1 BACKGROUND OF THE INVENTION ~-
2 l. Eield of the Invention
3 The present invention relates to an improved method for treating
4 subterranean, unconsolidated formation. In one aspect it relates to an improved method for preconditioning the wellbore prior to consolidating 6 the formation with synthetic resins.
7 2. Description of the Prior Art 8 Difficulties due to solids entrained in produced fluids have 9 led to sand control methods which employ a variety of different synthetic resins for the consolidation of incompetent subterranean formations.
11 These methods involve the injection of a liquid resin or a resin forming 12 material into the formation and permitting the resin to cure to an 13 infusible state, thereby bonding the formation sand in place. Typically, 14 a solvent is injected as a preflush into the formation to remove resident fluids and precondition the formation to be consolidated.
16 Often, the consolidation treatment is unsuccessful because of 17 contamination of the resin during injection by fluids contained in the 18 wellbore. These contaminating fluids often exist in the casing rathole 19 (i.e. that portion of the casing below a perforated zone adjacent the 20 unconsolidated formation). Typical contaminating fluids include water- -21 base completion fluids, seawater, and formation brine remaining from a 22 well completion or workover operation.
23 During sand consolidation treatments, the resin being injected into 24 the formation can displace a considerable amount of aqueous rathole contaminating fluid into the formation. This results in a continuous 26 contamination of the resin during injection, resulting in poor consolida-27 tion. Moreover, a significant amount of resin accumulates in the rathole 28 and is wasted.
29 A prior technique for dealing with the problem of contaminating fluid in the rathole involves circulating a high density brine into the ~-: , , . -:
1 rathole, resulting in a rathole fluid which the resin will not displace.
2 There are several problems with this method. In order to rapidly and 3 efficiently place the high density brine in the well, a pipe which 4 extends to the bottom of the rathole is necessary so that filling can take place from the bottom upwards. This necessitates the use of a 6 workover rig and increases costs. Another disadvantage is the incompatibi-7 lity of some consolidating fluids with the dense brine. Further, experience 8 has shown that simply mixing the dense brine for filling the rathhole is 9 an error-prone process. Finally, even if a high density brine is located in the rathole, contamination of the resin solution still takes place 11 during injection which can cause failure of the consolidation treatment.
13 The present invention provides an improved method of displacing 14 unwanted rathole fluids. Briefly, the method involves pumping a dense nonaqueous liquid into a cased wellbore to the level of the rathole 16 fluid, followed by injection of a preflush solution and a sand consolida-17 ting resin into the formation. The dense nonaqueous fluid immiscibly 18 displaces the aqueous rathole fluids which are removed from the formation 19 in the vicinity of the wellbore by the subsequent injection of the preflush solution. This effectively prevents contamination of the resin 21 when consolidating the formation.
22 The nonaqueous fluid is characterized by certain properties.
23 First, the displacing fluid must have a density which is greater than the 24 aqueous rathhole fluid and also greater than any of the subsequent consolidating fluids. Second, the displacing fluid should be immiscible 26 with the aqueous rathole fluid. Third, the displacing fluid should be 27 miscible with the consolidating preflush solution, if a preflush solution 28 is used in the consolidation treatment.
: .
1 In a preferred embodiment, the viscosity of the displacing 2 fluid must be such that a practical filling rate can be achieved and such 3 that removal of excess displacing fluid from the formation pore spaces is 4 facilitated. Also, the use of halogenated hydrocarbons is not preferred since such compounds, if produced together with other fluids, would tend 6 to cause difficulties at a later refining stage.
7 The present invention is described in detail below with particular 8 emphasis on the epoxy resin systems. However, it should be observed tha~
9 the principles exemplified by the invention are equally applicable to :
other systems that employ a resinous material in the consolidation of 11 incompetent subterranean formations, and which are sensitive to the 12 presence of aqueous rathole fluids.
14 The drawing is a plot comparing the compressive strength of a consolidated formation as a function of radial distance from the wellbore 16 for various rathole fluids.
': ' 18 Briefly, a plastic consolidation treatment of an incompetent 19 formation using an epoxy resin system catalyzed in situ involves the sequential introduction into the selected formation of a preflush solution, 21 a liquid reæin solution and a solution containing a curing agent or 22 catalyst. The curing agent or catalyst, upon contacting the resin, 23 initiates and accelerates polymerization, causing a rigid, permeable 24 sheath to be formed around the wellbore. The preflush solution is utilizedfor a variety of purposes in the pretreatmeant of the formation, including 26 removal of connate water to improve compressive strengths, preparation of 27 the formation sand grains to improve bonding and removal of local formation28 impairment.
1 The present invention involves the introduction of a dense, 2 nonaqueous fluid into the wellbore prior to injecting other consolidation 3 treatment solutions in order to displace aqueous fluids remaining in the 4 wellbore after previous well operations. These aqueous fluids are generallycontained in a lower portion of the wellbore below the interval over 6 which communication between the wellbore and the formation has been 7 established by casing perforations or otherwise. This lower portion is 8 commonly referred to as a rathole. While the following discussion assumes 9 that communication between the wellbore and formation has been established by perforating the casing over a selected interval, it should be understood 11 that other techniques may have been employed for this purpose, such as 12 milling to remove a portion of the casing. The practice of the method of 13 the present invention does not depend on the method of establishing 14 communication between the wellbore and the formation. It is sufficient that an opening has been established, using a~y suitable method, permitting 16 communication.
17 A typical source of the rathole fluids is the formation itself, 18 i.e. formation brine fills the rathole. Another source of aqueous rathole 19 fluid is from previous efforts to wash produced sand from the wellbore.
Usually, the unconsolidated formation has produced some sand into the 21 wellbore which must be washed out to some depth below the bottom perfora-22 tion. Common washing fluids include salt water and brine, a portion of 23 which usually remains in the rathole after washing the sand from the 24 wellbore. Finally, aqueous drilling fluids remaining from ordinary drilling operations may still be present in the rathole, although this 26 situation would not be common since the well has generally been circulated 27 with a clean fluid such as brine prior to perforating and producing.
28 A dense nonaqueous liquid useful for displacing rathole fluids 29 should be characterized by several properties. First, the displacing fluid should have a density greater than that of the rathole fluid or any 108258g 1 of the subsequent consolidating fluids. This is so that once the aqueous 2 rathole fluids are displaced, subsequent consolidating solutions will not 3 in turn displace the nonaqueous displacing fluid. As a practical matter, 4 the displacing fluid should have a minimum density of about 1.05 grams/cc and preferably a density of about 1.10 grams/cc or greater. Second, the 6 displacing fluid should be immiscible with the aqueous rathole fluid.
7 This eliminates the problem of mixing between the incoming dense fluids 8 and rathole fluids, and permits efficient gravity displacement from the 9 top downwards. As a practical matter, this means that an expensive workover rig is not needed in order to introduce the displacing fluid 11 into the wellbore. The nonaqueous displacing fluid may be introduced 12 simply by pumping the fluid into the casing at the surface, commonly 13 referred to as a bullhead technique. Third, the displacing fluid should 14 be miscible with the preflush solution, and preferably with the resin solution as well. This eliminates the problem of removing excess displacing 16 fluid from the formation pore spaces. Any excess displacing fluid which 17 enters the unconsolidated formation is removed from the formation in the 18 vicinity of the wellbore, along with the displaced aqueous rathole fluids, 19 by the normal quantities of preflush and resin solution.
Certain other practical considerations enter into the choice of 21 a suitable nonaqueous displacing fluid. First, to facilitate pumping of 22 the displacing fluids and also to facilitate removal of excess displacing 23 fluid from the formation, a suitable fluid should have a viscosity of 24 less than 100 centipoise at formation temperatures, and preferably less 25 than about 20 centipoise. This viscosity is similar to that of most -26 other consolidation fluids. Second, the displacing fluid should be 27 compatible with standard oil field and refining practices. Because 28 halogenated hydrocarbons are known to be harmful to many common refinery 29 catalysts, the use of such compounds is not preferred.
. . : ~
:108ZSff9 l Suitable nonaqueous displacing fluids that exhibit the above 2 described properties include ortho-nitrotoluene, carbon disulfide, 3 dimethylphthalate, nitrobenzene, and isoquinoline. Suitable fluids are 4 not limited to these examples, however, so long as the nonaqueous fluid used possesses the necessary characteristics. Combinations of different 6 non-aqueous fluids may also be utilized in practicing the method of the 7 present invention.
8 In a typical application of the present invention, the displacing 9 fluid is pumped directly into the casing at the wellhead. As mentioned previously, the portion of the wellbore from the perforations to the 11 surface generally contains either an aqueous fluid, such as brine remaining12 from perforation operations, or produced fluids. Thus, when pumping 13 operations are commenced, these fluids are forced into the formation.
14 The aqueous rathole fluids, however, will remain in place until the dense non-aqueous fluid reaches the level of the lowest perforations. The 16 dense fluid flows down to the formation perforations where displacement 17 of the aqueous rathole fluids takes place. Preferably, the displacing 18 fluid is continuously pumped during the displacement process. This 19 confines the displacement process to the rathole and also permits displace-ment to take place more rapidly, since the aqueous rathole fluids are 21 dynamically forced into the formation through the perforations.
22 In the preferred method, displacement of the aqueous rathole 23 fluids by the nonaqueous fluid is more than a simple gravity displacement 24 wherein the density difference of the fluids provides the only driving force. The preferred displacement process may be considered a dynamic 26 process since the displacement of the rathole fluid occurs as the nonaque-27 ous fluid is continuously pumped at the surface; while a major portion of 28 the nonaqueous fluid gravitates in the rathole to displace aqueous 29 fluids, a portion flows into the formation, forcing the aqueous rathole fluids into the formation and confining the gravity displacement process - . ~ ... . .
1 to the rathole. Thus, after the nonaqueous displacing fluid has been 2 pumped into the wellbore, the rathole will be completely filled with this 3 fluid. The aqueous rathole fluids will have been displaced into the 4 formation some distance. Further, any excess displacing fluid pumped becomes located in the formation immediately adjacent the wellbore and 6 some radial distance outward (although perhaps not the total radial 7 distance which will ultimately be consolidated, typically 3-4 feet).
8 The aqueous rathole fluids should be totally displaced since 9 any aqueous fluids remaining in the rathole would merely float on the ~O dense liquid, entering the formation incrementally when the resin or 11 preflush were pumped. Thus, an excess of displacing fluid is normally 12 used in order to provide a safety factor.
13 Typically, about 10 to about 12 barrels of nonaqueous displacing 14 fluid are required to fill a typical rathole of about 50 feet. Generally, adequate displacement rates are achieved by pumping at standard rates, 16 i.e. about one-half barrel per minute. Under these conditions, the 17 rathole can be filled with the nonaqueous fluids and the aqueous rathole 18 fluids displaced in about twenty minutes.
19 Once the dense nonaqueous fluid has been pumped and fills the rathole, a suitable preflush solution may be pumped into the casing at 21 the wellhead. Since all water is now confined to the formation, injection 22 of the preflush solution tends to displace all water (which would later 23 contaminate the resin solution if left in place) radially outwardly from 24 the formation volume to be consolidated. Moreover, by chosing a nonaqueousdisplacing fluid that is micible with the preflush solution, any excess 26 dense nonaqueous fluid is similarly displaced outwardly during injection 27 of the preflush solution.
28 Preferably, the preflush solution should have a density which 29 is less than both the nonaqueous displacing and the aqueous rathole fluid. This facilitates displacement of both fluidæ by the preflush ~, . . , ~ . ' 1 solution radially outwardly into the formation. However, this preferred 2 characteristic is more important where gravity displacement of the 3 aqueous fluid alone is utilized, as opposed to displacement under continuous 4 pumping. Thus, if the dense nonaqueous fluid is simply pumped to the level of the formation perforations and allowed to displace the aqueous 6 fluid with pumping stopped, the aqueous fluid will tend to remain in the 7 wellbore above the rathole. Subsequent injection of a preflush solution 8 having a density less than the aqueous fluid more effectively utilizes 9 the density difference of the aqueous fluid and preflush solution during displacement, thereby minimizing the volume of preflush solution necessary 11 to insure complete displacement of the aqueous fluid into the formation 12 as desired. It can be noted that most common preflush solutions inherently 13 possess the requisite density.
14 After injection of the preflush solution, a proper volume of resin solution is injected into the formation followed by the curing 16 agent or catalyst dissolved in a suitable solvent. Normally, from about 17 50 to about 75 gallons of resin solution per foot of interval to be 18 treated are used.
19 Since the nonaqueous fluid filling the rathole has a density greater than that of the resin solution, waste of the resin solution is 21 limited to the small amount which may be located between the lower 22 perforations and the top of the displacing fluids in the rathole. This 23 amount will be significantly less than the amount lost when the resin 24 solution is able to displace the rathole fluid. For example, the amount lost in the rathole when aqueous rathole fluids are not displaced may be 26 as much as 50 gallons.
27 Injection of the solution containing the curing agent or 28 catalyst displaces the resin from the pore spaces of the formation and 29 imparts the desired permeability to the invaded pore spaces. The curing agent or catalyst is extracted by the resin solution that remains in : . , ' . , ' : ~ .; - ' : :
~. , :
10825g9 1 contact with the sand grains. This causes the resin to harden, bonding 2 the sand grains together to consolidate the formation.
3 On the rare occasion where drilling mud remains in the rathole, 4 the greatest problem arises due to the separation of mud solids and water. A quantity of water may exist over a relatively short interval in 6 the rathole immediately below the bottom perforation (the exact distance 7 of the interval will be dependent on mud composition, length of time in 8 rathole and temperature). Generally, the drilling fluid suspension has a 9 much greater composite density than any of the consolidating chemicals and therefore displacement normally would seem to be unnecessary. However, 11 tests have shown that even a small amount of aqueous fluids below the 12 perforations, if not removed, can cause failure of the consolidation 13 treatment. The method of the present invention effectively removes such 14 aqueous fluids, with the only modification being a reduction in the volume of nonaqueous displacing fluid pumped into the wellbore.
16 Further details of an in situ cured epoxy treatment are described 17 in an article entitled "Externally Catalyzed Epoxy for Sand Control" by 18 F. A. Brooks, et. al., published in Journal of Petroleum Technology, 19 June, 1974.
Although the present invention has been described in relation 21 to an in situ cured method for placing epoxy resins, other methods of 22 placement and types of plastic consolidation treatments made be used.
23 Thus, the epoxy resins may be applied by an internally cured method 24 wherein a solution of the resin along with the curing agent or catalyst is injected into the formation. One such method is described at length 26 in an article entitled "Consolidation of Silty Sands With An Epoxy Resin 27 Overflush Process", by E. H. Richardson and T. W. Hamby, published in 28 Journal of Petroleum Technology, September, 1970. Also, the placement of 29 the various liquids may be accomplished by means of a workstring extending through the cased wellbore. Such methods and types of material will be 31 familiar to those skilled in the art.
..
1 As described in detail in the references noted above, the 2 consolidation treatments, in addition to the preflush solution, resin 3 solution and overflush liquids, may employ other liquids such as pre-4 acidizing treatment solutions, spacer liquids, and the like. Additives for the various solutions may include coupling agents, thickening agents, 6 surfactants, and the like.
7 ~ABORATORY EXPERIMENTS
8 In order to demonstrate the effect of the treatment according 9 to the present invention on the compressive strength and retained permeabi-lity of a consolidated interval, several consolidated samples were prepared 11 and subjected to compressive strength and permeability tests. A large 12 scale radial well bore model was constructed for performing the consolida-13 tion experiments. The model was triangular in shape, representing a 70 14 sector about a well, and had a radius of five feet and a thickness of one 15 foot. Damp Brazos River sand was used to pack the model. During consolida- ;
16 tion studies, the model was brought to a temperature of about 150 F, 17 representative of a typical formation temperature. Fluids were pumped 18 into the triangular model at scaled field rates. A pipe section, simulating 19 a wellbore and rathole, was located at one corner of the triangle, and extended below the model to provide a rathole of approximately 8 feet in 21 length. A single perforation was provided in the pipe section communicating 22 with the model formation.
23 Table l presents the experimental conditions for tests conducted 24 to compare the effect different fluids filling the pipe section of the test model had on a typical epoxy sand consolidation treatment. Identical 26 pumping rates, preflush, resin and catalyst solution volumes and concentra-27 tions, as well as identical consolidating materials were utilized in the 28 tests. The rathole, however, was filled with several different fluids 29 prior to pumping the consolidation chemicals in order to simulate the effect of different displacing fluids on the consolidation treatment.
, . . .
- 1082585~
1 Table 1 - EXPERIMENTAL CONDITIONS FOR RATHOLE FLUIDS TESTS
2 Fluid in Rathole 3 Low 4 Density Dense Brine Brine Nitrotoluene Seawater 6 Pu~p Rate 7 (bbl/min) 0.50 0.50 0.50 0.50 8 Preflush 9 Volume 10 (gal/ft) 80 80 80 80 11 Resin 12 Volume 13 (gal/ft) 55 55 55 55 14 Spacer 15 Oil Volume 16 (gal/ft) 40 30 30 30 17 Catalyst 18 Solution Volume 19 (gal/ft) 250 250 250 250 20 Initial 21 Permeability 22 (Darcy) 2.20 1.31 1.20 2.00 23 Consolidated 24 Radius 25 (inches) 43 43 35 41 26 Avg. Porosity 27 Initial42.3 40.4 42.0 39.6 :
28 Final 28.3 26.5 27.6 25.8 .: : :
:
~ ~082S89 ., 1 After consolidation, the formation was tested for compressive 2 strength and retained permeability. The results of these tests are 3 reported in Table 2.
4 Table 2 - EPFECT OF RATHOLE ELUID ON CONSOLIDATION TREATMENT
Rathole FluidComposite Permeability Average 6 During Consolidation Retention (%) Strength (psi) 7 Low density brine79% 4940 8 Dense brine 100b+ 4880 9 Seawater 100~+ 3310 Nitrotoluene 95% 5910 11 When sea water (8.5 pounds per gallon) filled the rathole, the 12 more dense resin (9.0 pounds per gallon) incrementally displaced the sea 13 water into the sand pack. As seen in the drawing, the displaced sea 14 water invaded the sand pack to a depth of about 16 inches and prevented the epoxy resin from adhering to the sand. The low compressive strength 16 in the formation O to 16 inches from the wellbore would probably lead to 17 an initial job failure, if obtained in a field application.
18 When dense brine (9.8 pounds per gallon) filled the rathole, 19 the resin solution tended to displace brine from about 3 inches of rathole directly below the perforation, perhaps due to turbulence around 21 the perforation. As seen in the drawing, this again resulted in a 22 relatively poor strength profile for the sand pack, reflecting the small 23 amount of water displaced.
10825~9 1 Superior results were obtained when the rathole was filled with 2 o-nitrotoluene (9.6 pounds per gallon). Because the wellbore did not 3 contain any water throughout the time of resin injection, maximum strength 4 was maintained throughout the entire sand pack, as seen in the drawing.
The average compressive strength of the sand pack was also much higher, 6 as reported in Table 2.
7 Again, it should be observed that the method of the present 8 invention may also be used with an internally-cured epoxy system, and 9 with other resin materials. It should be realized that the specific materials and procedures may differ somewhat from those described herein.
11 However, the principle exemplified by displacement of aqueous rathole 12 fluids with a nonaqueous fluid having the requisite physical characteristics 13 is equally applicable to such other systems.
The following field test illustrates a specific procedure for 16 performing the method of the present invention. A well completed in an 8 17 foot interval at about 8,900 feet was not capable of sustaining production 18 for long periods of time because of sand problems. A l-inch work string 19 was placed in the well and brine circulated therethrough to remove sand from the wellbore. A slurry of 10-15 mesh sand and brine was injected 21 through the perforations and pressure packed in place. Diesel oil was 22 then used to displace brine above the lowermost perforations. Following 23 an injectivity test to insure that the perforations were open, pumping 24 operations were commenced. The pumping schedule was as follows:
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~082S89 1 Tradename 2 or 3 Quantity Type Supplier
7 2. Description of the Prior Art 8 Difficulties due to solids entrained in produced fluids have 9 led to sand control methods which employ a variety of different synthetic resins for the consolidation of incompetent subterranean formations.
11 These methods involve the injection of a liquid resin or a resin forming 12 material into the formation and permitting the resin to cure to an 13 infusible state, thereby bonding the formation sand in place. Typically, 14 a solvent is injected as a preflush into the formation to remove resident fluids and precondition the formation to be consolidated.
16 Often, the consolidation treatment is unsuccessful because of 17 contamination of the resin during injection by fluids contained in the 18 wellbore. These contaminating fluids often exist in the casing rathole 19 (i.e. that portion of the casing below a perforated zone adjacent the 20 unconsolidated formation). Typical contaminating fluids include water- -21 base completion fluids, seawater, and formation brine remaining from a 22 well completion or workover operation.
23 During sand consolidation treatments, the resin being injected into 24 the formation can displace a considerable amount of aqueous rathole contaminating fluid into the formation. This results in a continuous 26 contamination of the resin during injection, resulting in poor consolida-27 tion. Moreover, a significant amount of resin accumulates in the rathole 28 and is wasted.
29 A prior technique for dealing with the problem of contaminating fluid in the rathole involves circulating a high density brine into the ~-: , , . -:
1 rathole, resulting in a rathole fluid which the resin will not displace.
2 There are several problems with this method. In order to rapidly and 3 efficiently place the high density brine in the well, a pipe which 4 extends to the bottom of the rathole is necessary so that filling can take place from the bottom upwards. This necessitates the use of a 6 workover rig and increases costs. Another disadvantage is the incompatibi-7 lity of some consolidating fluids with the dense brine. Further, experience 8 has shown that simply mixing the dense brine for filling the rathhole is 9 an error-prone process. Finally, even if a high density brine is located in the rathole, contamination of the resin solution still takes place 11 during injection which can cause failure of the consolidation treatment.
13 The present invention provides an improved method of displacing 14 unwanted rathole fluids. Briefly, the method involves pumping a dense nonaqueous liquid into a cased wellbore to the level of the rathole 16 fluid, followed by injection of a preflush solution and a sand consolida-17 ting resin into the formation. The dense nonaqueous fluid immiscibly 18 displaces the aqueous rathole fluids which are removed from the formation 19 in the vicinity of the wellbore by the subsequent injection of the preflush solution. This effectively prevents contamination of the resin 21 when consolidating the formation.
22 The nonaqueous fluid is characterized by certain properties.
23 First, the displacing fluid must have a density which is greater than the 24 aqueous rathhole fluid and also greater than any of the subsequent consolidating fluids. Second, the displacing fluid should be immiscible 26 with the aqueous rathole fluid. Third, the displacing fluid should be 27 miscible with the consolidating preflush solution, if a preflush solution 28 is used in the consolidation treatment.
: .
1 In a preferred embodiment, the viscosity of the displacing 2 fluid must be such that a practical filling rate can be achieved and such 3 that removal of excess displacing fluid from the formation pore spaces is 4 facilitated. Also, the use of halogenated hydrocarbons is not preferred since such compounds, if produced together with other fluids, would tend 6 to cause difficulties at a later refining stage.
7 The present invention is described in detail below with particular 8 emphasis on the epoxy resin systems. However, it should be observed tha~
9 the principles exemplified by the invention are equally applicable to :
other systems that employ a resinous material in the consolidation of 11 incompetent subterranean formations, and which are sensitive to the 12 presence of aqueous rathole fluids.
14 The drawing is a plot comparing the compressive strength of a consolidated formation as a function of radial distance from the wellbore 16 for various rathole fluids.
': ' 18 Briefly, a plastic consolidation treatment of an incompetent 19 formation using an epoxy resin system catalyzed in situ involves the sequential introduction into the selected formation of a preflush solution, 21 a liquid reæin solution and a solution containing a curing agent or 22 catalyst. The curing agent or catalyst, upon contacting the resin, 23 initiates and accelerates polymerization, causing a rigid, permeable 24 sheath to be formed around the wellbore. The preflush solution is utilizedfor a variety of purposes in the pretreatmeant of the formation, including 26 removal of connate water to improve compressive strengths, preparation of 27 the formation sand grains to improve bonding and removal of local formation28 impairment.
1 The present invention involves the introduction of a dense, 2 nonaqueous fluid into the wellbore prior to injecting other consolidation 3 treatment solutions in order to displace aqueous fluids remaining in the 4 wellbore after previous well operations. These aqueous fluids are generallycontained in a lower portion of the wellbore below the interval over 6 which communication between the wellbore and the formation has been 7 established by casing perforations or otherwise. This lower portion is 8 commonly referred to as a rathole. While the following discussion assumes 9 that communication between the wellbore and formation has been established by perforating the casing over a selected interval, it should be understood 11 that other techniques may have been employed for this purpose, such as 12 milling to remove a portion of the casing. The practice of the method of 13 the present invention does not depend on the method of establishing 14 communication between the wellbore and the formation. It is sufficient that an opening has been established, using a~y suitable method, permitting 16 communication.
17 A typical source of the rathole fluids is the formation itself, 18 i.e. formation brine fills the rathole. Another source of aqueous rathole 19 fluid is from previous efforts to wash produced sand from the wellbore.
Usually, the unconsolidated formation has produced some sand into the 21 wellbore which must be washed out to some depth below the bottom perfora-22 tion. Common washing fluids include salt water and brine, a portion of 23 which usually remains in the rathole after washing the sand from the 24 wellbore. Finally, aqueous drilling fluids remaining from ordinary drilling operations may still be present in the rathole, although this 26 situation would not be common since the well has generally been circulated 27 with a clean fluid such as brine prior to perforating and producing.
28 A dense nonaqueous liquid useful for displacing rathole fluids 29 should be characterized by several properties. First, the displacing fluid should have a density greater than that of the rathole fluid or any 108258g 1 of the subsequent consolidating fluids. This is so that once the aqueous 2 rathole fluids are displaced, subsequent consolidating solutions will not 3 in turn displace the nonaqueous displacing fluid. As a practical matter, 4 the displacing fluid should have a minimum density of about 1.05 grams/cc and preferably a density of about 1.10 grams/cc or greater. Second, the 6 displacing fluid should be immiscible with the aqueous rathole fluid.
7 This eliminates the problem of mixing between the incoming dense fluids 8 and rathole fluids, and permits efficient gravity displacement from the 9 top downwards. As a practical matter, this means that an expensive workover rig is not needed in order to introduce the displacing fluid 11 into the wellbore. The nonaqueous displacing fluid may be introduced 12 simply by pumping the fluid into the casing at the surface, commonly 13 referred to as a bullhead technique. Third, the displacing fluid should 14 be miscible with the preflush solution, and preferably with the resin solution as well. This eliminates the problem of removing excess displacing 16 fluid from the formation pore spaces. Any excess displacing fluid which 17 enters the unconsolidated formation is removed from the formation in the 18 vicinity of the wellbore, along with the displaced aqueous rathole fluids, 19 by the normal quantities of preflush and resin solution.
Certain other practical considerations enter into the choice of 21 a suitable nonaqueous displacing fluid. First, to facilitate pumping of 22 the displacing fluids and also to facilitate removal of excess displacing 23 fluid from the formation, a suitable fluid should have a viscosity of 24 less than 100 centipoise at formation temperatures, and preferably less 25 than about 20 centipoise. This viscosity is similar to that of most -26 other consolidation fluids. Second, the displacing fluid should be 27 compatible with standard oil field and refining practices. Because 28 halogenated hydrocarbons are known to be harmful to many common refinery 29 catalysts, the use of such compounds is not preferred.
. . : ~
:108ZSff9 l Suitable nonaqueous displacing fluids that exhibit the above 2 described properties include ortho-nitrotoluene, carbon disulfide, 3 dimethylphthalate, nitrobenzene, and isoquinoline. Suitable fluids are 4 not limited to these examples, however, so long as the nonaqueous fluid used possesses the necessary characteristics. Combinations of different 6 non-aqueous fluids may also be utilized in practicing the method of the 7 present invention.
8 In a typical application of the present invention, the displacing 9 fluid is pumped directly into the casing at the wellhead. As mentioned previously, the portion of the wellbore from the perforations to the 11 surface generally contains either an aqueous fluid, such as brine remaining12 from perforation operations, or produced fluids. Thus, when pumping 13 operations are commenced, these fluids are forced into the formation.
14 The aqueous rathole fluids, however, will remain in place until the dense non-aqueous fluid reaches the level of the lowest perforations. The 16 dense fluid flows down to the formation perforations where displacement 17 of the aqueous rathole fluids takes place. Preferably, the displacing 18 fluid is continuously pumped during the displacement process. This 19 confines the displacement process to the rathole and also permits displace-ment to take place more rapidly, since the aqueous rathole fluids are 21 dynamically forced into the formation through the perforations.
22 In the preferred method, displacement of the aqueous rathole 23 fluids by the nonaqueous fluid is more than a simple gravity displacement 24 wherein the density difference of the fluids provides the only driving force. The preferred displacement process may be considered a dynamic 26 process since the displacement of the rathole fluid occurs as the nonaque-27 ous fluid is continuously pumped at the surface; while a major portion of 28 the nonaqueous fluid gravitates in the rathole to displace aqueous 29 fluids, a portion flows into the formation, forcing the aqueous rathole fluids into the formation and confining the gravity displacement process - . ~ ... . .
1 to the rathole. Thus, after the nonaqueous displacing fluid has been 2 pumped into the wellbore, the rathole will be completely filled with this 3 fluid. The aqueous rathole fluids will have been displaced into the 4 formation some distance. Further, any excess displacing fluid pumped becomes located in the formation immediately adjacent the wellbore and 6 some radial distance outward (although perhaps not the total radial 7 distance which will ultimately be consolidated, typically 3-4 feet).
8 The aqueous rathole fluids should be totally displaced since 9 any aqueous fluids remaining in the rathole would merely float on the ~O dense liquid, entering the formation incrementally when the resin or 11 preflush were pumped. Thus, an excess of displacing fluid is normally 12 used in order to provide a safety factor.
13 Typically, about 10 to about 12 barrels of nonaqueous displacing 14 fluid are required to fill a typical rathole of about 50 feet. Generally, adequate displacement rates are achieved by pumping at standard rates, 16 i.e. about one-half barrel per minute. Under these conditions, the 17 rathole can be filled with the nonaqueous fluids and the aqueous rathole 18 fluids displaced in about twenty minutes.
19 Once the dense nonaqueous fluid has been pumped and fills the rathole, a suitable preflush solution may be pumped into the casing at 21 the wellhead. Since all water is now confined to the formation, injection 22 of the preflush solution tends to displace all water (which would later 23 contaminate the resin solution if left in place) radially outwardly from 24 the formation volume to be consolidated. Moreover, by chosing a nonaqueousdisplacing fluid that is micible with the preflush solution, any excess 26 dense nonaqueous fluid is similarly displaced outwardly during injection 27 of the preflush solution.
28 Preferably, the preflush solution should have a density which 29 is less than both the nonaqueous displacing and the aqueous rathole fluid. This facilitates displacement of both fluidæ by the preflush ~, . . , ~ . ' 1 solution radially outwardly into the formation. However, this preferred 2 characteristic is more important where gravity displacement of the 3 aqueous fluid alone is utilized, as opposed to displacement under continuous 4 pumping. Thus, if the dense nonaqueous fluid is simply pumped to the level of the formation perforations and allowed to displace the aqueous 6 fluid with pumping stopped, the aqueous fluid will tend to remain in the 7 wellbore above the rathole. Subsequent injection of a preflush solution 8 having a density less than the aqueous fluid more effectively utilizes 9 the density difference of the aqueous fluid and preflush solution during displacement, thereby minimizing the volume of preflush solution necessary 11 to insure complete displacement of the aqueous fluid into the formation 12 as desired. It can be noted that most common preflush solutions inherently 13 possess the requisite density.
14 After injection of the preflush solution, a proper volume of resin solution is injected into the formation followed by the curing 16 agent or catalyst dissolved in a suitable solvent. Normally, from about 17 50 to about 75 gallons of resin solution per foot of interval to be 18 treated are used.
19 Since the nonaqueous fluid filling the rathole has a density greater than that of the resin solution, waste of the resin solution is 21 limited to the small amount which may be located between the lower 22 perforations and the top of the displacing fluids in the rathole. This 23 amount will be significantly less than the amount lost when the resin 24 solution is able to displace the rathole fluid. For example, the amount lost in the rathole when aqueous rathole fluids are not displaced may be 26 as much as 50 gallons.
27 Injection of the solution containing the curing agent or 28 catalyst displaces the resin from the pore spaces of the formation and 29 imparts the desired permeability to the invaded pore spaces. The curing agent or catalyst is extracted by the resin solution that remains in : . , ' . , ' : ~ .; - ' : :
~. , :
10825g9 1 contact with the sand grains. This causes the resin to harden, bonding 2 the sand grains together to consolidate the formation.
3 On the rare occasion where drilling mud remains in the rathole, 4 the greatest problem arises due to the separation of mud solids and water. A quantity of water may exist over a relatively short interval in 6 the rathole immediately below the bottom perforation (the exact distance 7 of the interval will be dependent on mud composition, length of time in 8 rathole and temperature). Generally, the drilling fluid suspension has a 9 much greater composite density than any of the consolidating chemicals and therefore displacement normally would seem to be unnecessary. However, 11 tests have shown that even a small amount of aqueous fluids below the 12 perforations, if not removed, can cause failure of the consolidation 13 treatment. The method of the present invention effectively removes such 14 aqueous fluids, with the only modification being a reduction in the volume of nonaqueous displacing fluid pumped into the wellbore.
16 Further details of an in situ cured epoxy treatment are described 17 in an article entitled "Externally Catalyzed Epoxy for Sand Control" by 18 F. A. Brooks, et. al., published in Journal of Petroleum Technology, 19 June, 1974.
Although the present invention has been described in relation 21 to an in situ cured method for placing epoxy resins, other methods of 22 placement and types of plastic consolidation treatments made be used.
23 Thus, the epoxy resins may be applied by an internally cured method 24 wherein a solution of the resin along with the curing agent or catalyst is injected into the formation. One such method is described at length 26 in an article entitled "Consolidation of Silty Sands With An Epoxy Resin 27 Overflush Process", by E. H. Richardson and T. W. Hamby, published in 28 Journal of Petroleum Technology, September, 1970. Also, the placement of 29 the various liquids may be accomplished by means of a workstring extending through the cased wellbore. Such methods and types of material will be 31 familiar to those skilled in the art.
..
1 As described in detail in the references noted above, the 2 consolidation treatments, in addition to the preflush solution, resin 3 solution and overflush liquids, may employ other liquids such as pre-4 acidizing treatment solutions, spacer liquids, and the like. Additives for the various solutions may include coupling agents, thickening agents, 6 surfactants, and the like.
7 ~ABORATORY EXPERIMENTS
8 In order to demonstrate the effect of the treatment according 9 to the present invention on the compressive strength and retained permeabi-lity of a consolidated interval, several consolidated samples were prepared 11 and subjected to compressive strength and permeability tests. A large 12 scale radial well bore model was constructed for performing the consolida-13 tion experiments. The model was triangular in shape, representing a 70 14 sector about a well, and had a radius of five feet and a thickness of one 15 foot. Damp Brazos River sand was used to pack the model. During consolida- ;
16 tion studies, the model was brought to a temperature of about 150 F, 17 representative of a typical formation temperature. Fluids were pumped 18 into the triangular model at scaled field rates. A pipe section, simulating 19 a wellbore and rathole, was located at one corner of the triangle, and extended below the model to provide a rathole of approximately 8 feet in 21 length. A single perforation was provided in the pipe section communicating 22 with the model formation.
23 Table l presents the experimental conditions for tests conducted 24 to compare the effect different fluids filling the pipe section of the test model had on a typical epoxy sand consolidation treatment. Identical 26 pumping rates, preflush, resin and catalyst solution volumes and concentra-27 tions, as well as identical consolidating materials were utilized in the 28 tests. The rathole, however, was filled with several different fluids 29 prior to pumping the consolidation chemicals in order to simulate the effect of different displacing fluids on the consolidation treatment.
, . . .
- 1082585~
1 Table 1 - EXPERIMENTAL CONDITIONS FOR RATHOLE FLUIDS TESTS
2 Fluid in Rathole 3 Low 4 Density Dense Brine Brine Nitrotoluene Seawater 6 Pu~p Rate 7 (bbl/min) 0.50 0.50 0.50 0.50 8 Preflush 9 Volume 10 (gal/ft) 80 80 80 80 11 Resin 12 Volume 13 (gal/ft) 55 55 55 55 14 Spacer 15 Oil Volume 16 (gal/ft) 40 30 30 30 17 Catalyst 18 Solution Volume 19 (gal/ft) 250 250 250 250 20 Initial 21 Permeability 22 (Darcy) 2.20 1.31 1.20 2.00 23 Consolidated 24 Radius 25 (inches) 43 43 35 41 26 Avg. Porosity 27 Initial42.3 40.4 42.0 39.6 :
28 Final 28.3 26.5 27.6 25.8 .: : :
:
~ ~082S89 ., 1 After consolidation, the formation was tested for compressive 2 strength and retained permeability. The results of these tests are 3 reported in Table 2.
4 Table 2 - EPFECT OF RATHOLE ELUID ON CONSOLIDATION TREATMENT
Rathole FluidComposite Permeability Average 6 During Consolidation Retention (%) Strength (psi) 7 Low density brine79% 4940 8 Dense brine 100b+ 4880 9 Seawater 100~+ 3310 Nitrotoluene 95% 5910 11 When sea water (8.5 pounds per gallon) filled the rathole, the 12 more dense resin (9.0 pounds per gallon) incrementally displaced the sea 13 water into the sand pack. As seen in the drawing, the displaced sea 14 water invaded the sand pack to a depth of about 16 inches and prevented the epoxy resin from adhering to the sand. The low compressive strength 16 in the formation O to 16 inches from the wellbore would probably lead to 17 an initial job failure, if obtained in a field application.
18 When dense brine (9.8 pounds per gallon) filled the rathole, 19 the resin solution tended to displace brine from about 3 inches of rathole directly below the perforation, perhaps due to turbulence around 21 the perforation. As seen in the drawing, this again resulted in a 22 relatively poor strength profile for the sand pack, reflecting the small 23 amount of water displaced.
10825~9 1 Superior results were obtained when the rathole was filled with 2 o-nitrotoluene (9.6 pounds per gallon). Because the wellbore did not 3 contain any water throughout the time of resin injection, maximum strength 4 was maintained throughout the entire sand pack, as seen in the drawing.
The average compressive strength of the sand pack was also much higher, 6 as reported in Table 2.
7 Again, it should be observed that the method of the present 8 invention may also be used with an internally-cured epoxy system, and 9 with other resin materials. It should be realized that the specific materials and procedures may differ somewhat from those described herein.
11 However, the principle exemplified by displacement of aqueous rathole 12 fluids with a nonaqueous fluid having the requisite physical characteristics 13 is equally applicable to such other systems.
The following field test illustrates a specific procedure for 16 performing the method of the present invention. A well completed in an 8 17 foot interval at about 8,900 feet was not capable of sustaining production 18 for long periods of time because of sand problems. A l-inch work string 19 was placed in the well and brine circulated therethrough to remove sand from the wellbore. A slurry of 10-15 mesh sand and brine was injected 21 through the perforations and pressure packed in place. Diesel oil was 22 then used to displace brine above the lowermost perforations. Following 23 an injectivity test to insure that the perforations were open, pumping 24 operations were commenced. The pumping schedule was as follows:
.
~082S89 1 Tradename 2 or 3 Quantity Type Supplier
5 Acid Solution
6 15% HCl 300 gal 15% HCl
7 Mud Acid 750 gal 3% HF-12% HCl -
8 NeutralizerlOOO gal H2O, NH4Cl,
9 NH4HC03 lONonaqueous Displacing 11 Fluid 12Nitrotoluene300 gal o-nitro- DuPont 13 toluene 14Preflush Solvent :~
15Ethylene glycol/800 gal Solvent Union 16isopropyl etherAC Carbide 17Thickening agent 32 lb PVP(K-90) GAF Corp.
18Coupling agent 4 gal Z-6020 Dow Corning 19Resin Solution :
20 Epoxy resin 293 gal XD-7818 Dow Chemical 21Acetone/Cyclohexane149 gal 22Spacer Fluid 23 Refined Oil 160 gal. Mentor 28 Exxon Co., 24 USA ~:
25 Refined Oil 80 gal Flexon 766 Exxon Co., 26 USA : :
27Catalyst Solution 28 Refined Oil 1340 gal Mentor 28 Exxon Co., .:
30 Refined Oil 660 gal Flexon 766 Exxon Co., 32Catalyst (tertiary60 gal DMP-30 Rohm and 33 amine) Haas , - . . .
, . , .. ~ . . .
1082S~9 1 The various liquids were injected through the work string and 2 into the formation in the above sequence at a rate of about 20 gallons 3 per minute. The final solution was displaced from the workover string 4 with diesel oil and the well was shut in to permit the resin to cure.
When the well was returned to production, produced fluids were sand free 6 indicating initial success of the treatment.
7 The laboratory tests and actual field test described above, 8 respectively demonstrate the benefits and applicability of the method of 9 the present invention in sand consolidation treatments.
.: -'' ~:
15Ethylene glycol/800 gal Solvent Union 16isopropyl etherAC Carbide 17Thickening agent 32 lb PVP(K-90) GAF Corp.
18Coupling agent 4 gal Z-6020 Dow Corning 19Resin Solution :
20 Epoxy resin 293 gal XD-7818 Dow Chemical 21Acetone/Cyclohexane149 gal 22Spacer Fluid 23 Refined Oil 160 gal. Mentor 28 Exxon Co., 24 USA ~:
25 Refined Oil 80 gal Flexon 766 Exxon Co., 26 USA : :
27Catalyst Solution 28 Refined Oil 1340 gal Mentor 28 Exxon Co., .:
30 Refined Oil 660 gal Flexon 766 Exxon Co., 32Catalyst (tertiary60 gal DMP-30 Rohm and 33 amine) Haas , - . . .
, . , .. ~ . . .
1082S~9 1 The various liquids were injected through the work string and 2 into the formation in the above sequence at a rate of about 20 gallons 3 per minute. The final solution was displaced from the workover string 4 with diesel oil and the well was shut in to permit the resin to cure.
When the well was returned to production, produced fluids were sand free 6 indicating initial success of the treatment.
7 The laboratory tests and actual field test described above, 8 respectively demonstrate the benefits and applicability of the method of 9 the present invention in sand consolidation treatments.
.: -'' ~:
Claims (16)
OR PRIVILEGE IS CLAIMED ARE DEFINED AS FOLLOWS:
1. A method of consolidating an imcompetent subterranean formation surrounding a cased wellbore wherein the casing has an in-termediate perforated interval opposite said formation which comprises;
(a) pumping a nonaqueous fluid down said wellbore to displace substantially all of the fluid in said casing below said perforated interval and to force the displaced well fluid into said formation, said nonaqueous fluid having a density greater than said well fluid, (b) pumping a preflush solution having a density less than said nonaqueous fluid down said wellbore and into said formation;
(c) pumping a resinous material having a density less than said nonaqueous fluid down said wellbore and into said formation; and (d) allowing said resinous material to harden thereby con-solidating a portion of said formation.
(a) pumping a nonaqueous fluid down said wellbore to displace substantially all of the fluid in said casing below said perforated interval and to force the displaced well fluid into said formation, said nonaqueous fluid having a density greater than said well fluid, (b) pumping a preflush solution having a density less than said nonaqueous fluid down said wellbore and into said formation;
(c) pumping a resinous material having a density less than said nonaqueous fluid down said wellbore and into said formation; and (d) allowing said resinous material to harden thereby con-solidating a portion of said formation.
2. The method of claim 1 wherein said nonaqueous fluid has a density of greater than about 1.05 g/cc.
3. The method of claim 2 wherein said nonaqueous fluid has a density of greater than about 1.10 g/cc.
4. The method of claim 3 wherein said nonaqueous fluid is substantially free of halogens.
5. The method of claim 1 wherein said nonaqueous fluid is miscible with said preflush solution, and immiscible with the fluids contained in said wellbore below said interval.
6. The method of claim 5 wherein said nonaqueous liquid is miscible with said solution containing resinous material.
7. The method of claim l wherein said nonaqueous liquid includes a liquid selected from the group consisting of o-nitrotoluene, carbon disulfide, dimethylphthalate, nitrobenzene and isoquinoline.
8. The method as defined in claim 1 wherein the steps of pumping said nonaqueous fluid, said preflush solution, and said resinous material is performed through said casing.
9. In a method for the consolidation of an imcompetent sub-terranean formation surrounding a cased wellbore having an opening therein providing a fluid communication between said wellbore and said formation wherein a resinous material is injected into the formation and allowed to harden, said wellbore containing an aqueous, resin-contaminating fluid in a portion of said wellbore below the level of said opening, the im-provement which comprises, prior to injecting said resinous material, immiscibly displacing said contaminating fluid from said portion with a nonaqueous fluid which has a density greater than the density of said contaminating fluid and said resinous material to force said resin-contaminating fluid into said formation, thereafter injecting a preflush fluid into said formation which is partially miscible with both the aqueous contaminating fluid and the nonaqueous fluid.
10. The method of claim 9 wherein said nonaqueous fluid is miscible with said resinous material.
11. The method of claim 9 wherein said nonaqueous fluid has a viscosity of less than about 100 centipoise.
12. The method of claim 11 wherein the viscosity of said nonaqueous liquid is less than about 20 centipoise,
13. The method of claim 9 wherein said nonaqueous fluid is substantially free of halogenated material.
14. A method of consolidating an incompetent formation surrounding a cased wellbore having a perforated interval opposite said formation and containing an aqueous fluid in a lower portion thereof which comprises:
(a) forcing substantially all of the aqueous fluid from said lower portion of said wellbore and into said formation by introducing a nonaqueous fluid into said wellbore, said nonaqueous fluid being immiscible with said aqueous fluid and having a density greater than said aqueous fluid;
(b) further displacing said aqueous fluid radially out-wardly into said formation by pumping a preflush solution into said formation, said preflush solution being at least partially miscible with both said aqueous fluid and said nonaqueous fluid and having a density less than said nonaqueous fluid;
(c) pumping into said formation a resin solution which is miscible with said nonaqueous fluid and has a density less than said nonaqueous fluid; and (d) permitting said resin to harden such that said formation is consolidated.
(a) forcing substantially all of the aqueous fluid from said lower portion of said wellbore and into said formation by introducing a nonaqueous fluid into said wellbore, said nonaqueous fluid being immiscible with said aqueous fluid and having a density greater than said aqueous fluid;
(b) further displacing said aqueous fluid radially out-wardly into said formation by pumping a preflush solution into said formation, said preflush solution being at least partially miscible with both said aqueous fluid and said nonaqueous fluid and having a density less than said nonaqueous fluid;
(c) pumping into said formation a resin solution which is miscible with said nonaqueous fluid and has a density less than said nonaqueous fluid; and (d) permitting said resin to harden such that said formation is consolidated.
15. The method of claim 14 wherein said resin solution contains an epoxy resin.
16. The method of claim 14 wherein said nonaqueous fluid includes a fluid selected from the group consisting of o-nitrotoluene, carbon disulfide, dlmethylphthalate, nitrobenzene, and isoquinoline.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US81400977A | 1977-07-08 | 1977-07-08 | |
| US814,009 | 1977-07-08 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1082589A true CA1082589A (en) | 1980-07-29 |
Family
ID=25213977
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA305,936A Expired CA1082589A (en) | 1977-07-08 | 1978-06-21 | Method of consolidating a subterranean formation |
Country Status (5)
| Country | Link |
|---|---|
| US (1) | US4137971A (en) |
| CA (1) | CA1082589A (en) |
| GB (1) | GB2000827B (en) |
| MY (1) | MY8500283A (en) |
| NO (1) | NO148684C (en) |
Families Citing this family (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4860830A (en) * | 1988-08-05 | 1989-08-29 | Mobil Oil Corporation | Method of cleaning a horizontal wellbore |
| US4972906A (en) * | 1989-09-07 | 1990-11-27 | Conoco Inc. | Method for selective plugging of a zone in a well |
| US5293939A (en) * | 1992-07-31 | 1994-03-15 | Texaco Chemical Company | Formation treating methods |
| GB2332221A (en) | 1997-12-13 | 1999-06-16 | Sofitech Nv | Stabilising clayey formations |
| GB2363810B (en) * | 2000-06-21 | 2003-03-26 | Sofitech Nv | Processes for treating subterranean formations |
Family Cites Families (12)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3123138A (en) * | 1964-03-03 | robichaux | ||
| US3055426A (en) * | 1959-02-05 | 1962-09-25 | Jersey Prod Res Co | Method for consolidating incompetent subsurface earth zones |
| US3090435A (en) * | 1959-02-05 | 1963-05-21 | Jersey Prod Res Co | Method for consolidating incompetent formations |
| US3199590A (en) * | 1963-02-25 | 1965-08-10 | Halliburton Co | Method of consolidating incompetent sands and composition therefor |
| US3250330A (en) * | 1963-10-31 | 1966-05-10 | Shell Oil Co | Process for treating earth formations |
| US3339633A (en) * | 1965-07-27 | 1967-09-05 | Shell Oil Co | Polyepoxide consolidation of earthern materials |
| US3384176A (en) * | 1966-10-03 | 1968-05-21 | Gulf Research Development Co | Method of fracturing using dense liquid to direct propping agent into the fracture |
| GB1168945A (en) * | 1968-03-15 | 1969-10-29 | Shell Int Research | Method for Treating a Part of a Permeable Formation |
| US3718189A (en) * | 1969-07-30 | 1973-02-27 | Exxon Production Research Co | Consolidation of incompetent formations |
| US3759327A (en) * | 1972-01-07 | 1973-09-18 | Halliburton Co | Internally catalyzed well consolidation method |
| US3902557A (en) * | 1974-03-25 | 1975-09-02 | Exxon Production Research Co | Treatment of wells |
| US3915232A (en) * | 1974-08-27 | 1975-10-28 | Exxon Production Research Co | Method of consolidating incompetent formations |
-
1978
- 1978-02-17 US US05/878,631 patent/US4137971A/en not_active Expired - Lifetime
- 1978-06-21 CA CA305,936A patent/CA1082589A/en not_active Expired
- 1978-07-06 NO NO782359A patent/NO148684C/en unknown
- 1978-07-06 GB GB7829035A patent/GB2000827B/en not_active Expired
-
1985
- 1985-12-30 MY MY283/85A patent/MY8500283A/en unknown
Also Published As
| Publication number | Publication date |
|---|---|
| NO148684B (en) | 1983-08-15 |
| NO148684C (en) | 1983-11-23 |
| MY8500283A (en) | 1985-12-31 |
| GB2000827B (en) | 1982-01-06 |
| GB2000827A (en) | 1979-01-17 |
| NO782359L (en) | 1979-01-09 |
| US4137971A (en) | 1979-02-06 |
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